In the process of producing hydrocarbons, most wells also produce significant amounts of water. This percentage of the produced fluids that consists of water or brine is known as the watercut. Most wells produce with an ever increasing watercut throughout their productive life. In fact, the end of a well's productive life is often determined by the watercut; a well is typically shut in when the value of the hydrocarbons produced is no longer sufficient to economically cover the operating costs of the well and the cost of disposing of the water.
Not only does the watercut affect the profitability of most wells, since the higher the watercut the lower the percentage of the production that consists of hydrocarbons, but the watercut also directly affects the operation costs. This is because in most wells, the disposal cost of handling the watercut includes the operating costs of bringing the water to the surface, separating the water from the hydrocarbons, and disposing of the separated water, often by re-injecting the water back into the subsurface. Therefore, decreasing the watercut of a well directly increases the value of the produced fluids and directly decreases the disposal costs.
One method of reducing the watercut of a well is to separate the water from the hydrocarbons downhole, rather than at the surface. Downhole separation increases the value of the fluids produced to the surface. Downhole separation also facilitates downhole disposal of the separated water. The separated water can be reinjected into the same production interval or into a different production interval. Separation can be achieved naturally, through gravity, or mechanically, for example through the use of a centrifuge. However, a mechanical separator greatly complicates well maintenance. Injection zones are prone to plugging and where mechanical separation is employed, correction of the plugging first requires removal of the separator.
Another way to improve the productivity of a well is to increase the length of the intersection of the productive interval by the well completion. One way of increasing this intersection length is through the use of multi-lateral wells. A multi-lateral well is a conventional well that has an additional “leg” or lateral well that is drilled from a point in the original well. The lateral well increases productivity by allowing additional intersection length along the productive interval without the cost and delay involved in re-drilling the upper part of the well. While multi-laterals enable multiple intersections within the same productive interval, multi-laterals also enable the intersection of different productive intervals within a reservoir. The use of multi-laterals increases the potential production of a well and can enable alternate water disposal locations, in the event that reinjection to the same productive interval is undesired.
Methods employing mechanical downhole separation have been taught for use in both conventional and multi-lateral wells. However, application of mechanical downhole separation has been limited, perhaps because of the difficulties and costs involved in repairing plugged injection zones. As discussed above with reference to conventional wells, these teachings that combine the use of mechanical downhole separation of the produced water and hydrocarbons with multi-laterals typically involve the use of a centrifuge to separate the production fluids. Just as in conventional wells, there are several drawbacks to these methods: they are mechanically complex; expensive to install; difficult to repair; and if access to the injection zone is required, then the separator must first be removed.
Accordingly, there remains a need for a method of production which extends the economic and productive life of a well by reducing the watercut, and thereby, reducing the operating and water disposal costs while avoiding the added expense, complexities and repair limitations inherent in the currently known methods.